Overview of Natural Gas in California

Natural Gas Supply

Most natural gas consumed in the United States is produced here, although some is imported from Canada or shipped as liquefied natural gas. Technological developments in exploration, drilling, well completion, and well stimulation in the oil and gas industry are expanding the amount of economically recoverable natural gas in the United States since 2006. As a result, production of natural gas has been increasing since 2006. Some natural gas-bearing formations such as shale reservoirs, once infeasible to extract, are now producing (or will be producing) in 31 states in the Lower 48 region. In 2012, total production climbed to 65.8 billion cubic feet per day (Bcf/d), with shale gas representing 44% or 29.0 Bcf/d according to industry sources.

In the mid-1990s, horizontal drilling combined with hydraulic fracturing started what many now call the natural gas revolution. Field operators can perforate more footage and multi-stage hydraulic fracturing, the most notable technological innovation, can stimulate far lengthier zones within the formation of interest. This stimulation process involves the pumping of a sand-laden viscous fluid, usually water, into the wellbore and into the formation. Sand and water makes up about 99.5 percent of the mixture and chemicals the remaining 0.5 percent. The operational pressure cracks the rock formation and creates an extensive network of artificial fractures, with each fracture open to a width of no more than two centimeters.1 Usually, these fractures extend up to hundreds of feet from the well bore.

Fractures held open by the proppant allow greater natural gas flow to the wellbore, and thus to the wellhead. In many instances, initial production may experience more than a ten- or twenty-fold increase after stimulation. As a result of the technological developments in exploration, drilling, and completion, low effective permeability no longer hinders production from tight sandstone and shale formations.

Figure 1 demonstrates a typical 'fracking' operation in a horizontal well along with the creation of a network of artificial fractures after the hydraulic fracturing treatment. The schematic also displays a typical multi-stage or multi-zone outcome of the subsurface treatment.

In California, hydraulic fracturing procedures tend to crack the rock along a narrow vertical band, generally starting at a point several thousand feet underground. As a result, the network of artificial fractures extends only tens to hundreds of feet away from the well (wellbore). Most of California's oil and gas production has been from vertical wells drilled into traditional oil and natural gas reservoirs (formations). Operators in California have executed few, if any, hydraulic fracturing jobs in horizontal wells.

The Monterey shale, a mostly oil "play" located in the San Joaquin Valley, contains about 15 billion barrels of oil and natural gas liquids and an undetermined volume of associated natural gas, according to an estimate prepared for the U.S. EIA in 2011.2 Due to numerous fault lines and pressure from historic seismic activity, the sedimentary strata of the Monterey shale are bent into folds. This folding formation is not as conducive to horizontal drilling as the Bakken or Marcellus shale deposits.3 Some industry experts believe that performing advanced, three-dimensional seismic surveys will be necessary before the Monterey shale can be extensively developed.4

3 The Bakken shale formation (predominantly oil) and Marcellus shale formation (predominantly gas) are located in North Dakota and neighboring states and Pennsylvania and neighboring states, respectively. They are the most prolific hydraulically fractured shale plays in the United States, and are used in this case for the sake of comparison to the Monterey shale formation, which has a very different geologic structure than either of them.

Natural Gas Demand

Natural gas is used for everything from generating electricity to cooking and space heating to an alternative transportation fuel. In 2012, total natural gas demand in California for industrial, residential, commercial, and electric power generation was 2,313 billion cubic feet per year (Bcf/year), up from 2,196 Bcf/year in 2010 (Table 1). Demand in all sectors except electric power generation remained relatively flat for the last decade due in large part to energy efficiency measures, but demand for power generation rose about 30 percent between 2011 and 2012.

Table 1: Natural Gas Demand in California by End Use from 2010 to 2012

Natural Gas Demand by End Use (Bcf/y)

2010

2011

2012

Residential

509

519

485

Commercial

199

201

201

Industrial

548

559

577

NG Vehicle

18

16

17

Electric Power

922

796

1032

Total Natural Gas Demand

2,196

2,091

2,313

Over 90 percent of households with gas service have gas heating, which accounted for 46 percent of all residential gas consumption in 2012. Water heating, including that for clothes washers and dishwashers, consumes the second largest portion at 42 percent, as shown in Table 2.

Table 2: Residential Natural Gas Consumption, 2012

Residential Natural Gas Consumption

Thousand of Therms Per Year (Mtherms/y)

Percentage

Water Heating

2,633

41.71%

Clothes Dryer

228

3.61%

Cooking

434

6.88%

Pools and Spas

141

2.24%

Space Heating

2,876

45.56%

TOTAL

6,312

100%

Natural gas residential energy efficiency savings from appliance and building standards totaled 3,812 million therms in 2012. Building and appliance standards have had a proportionally larger impact on residential natural gas than on electricity or commercial gas use. Residential standards account for natural gas demand savings of 21 percent in 1990 compared to a 1975 baseline, 33 percent in 2000, and 39 percent in 2010. Commercial standards account for demand savings of 3.8 percent in 1990, 7.0 percent in 2000, and 9.3 percent in 2010.

Except for the industrial and petroleum extraction sectors, natural gas demand is seasonal. In the winter, natural gas consumption spikes as residential and commercial customers ramp up space heating. For gas used in electric generation, periods of warmer weather increase demand for air conditioning. These seasonal trends affect both the overall demand for natural gas and the requirements of pipelines and storage to deliver the gas when it is needed and store it when it is not.

Natural Gas to Generate Electricity

Natural gas-fired generation has become the dominant source of electricity in California, as it fuels about 43 percent of electricity consumption followed by hydroelectric power. 8 Because natural gas is a dispatchable resource that provides load when the availability of hydroelectric power generation and/or other sources decrease, use varies greatly from year to year. The availability of hydroelectric resources, the emergence of renewable resources for electricity generation, and overall consumer demand are the variables that shape natural gas use in electric generation. Due to above average precipitation in 2011, natural gas used for electricity generation was 617 billion cubic feet (Bcf), compared to lower precipitation years in 2010 and 2012 when gas use for electric generation was 736 Bcf and 855 Bcf, respectively. 9

The thermal efficiency of California's gas-fired generation improved more than 22 percent between 2001 and 2012 because of an increased reliance upon combined cycle power plants and reduced dependence upon aging power plants. Moreover, the average heat rate of all gas-fired generation, excluding cogeneration, declined from 9,997 Btu/kWh to 7,805 Btu/kWh between 2001 and 2012. 10 The less efficient generation may still serve peaking, ramping, and reliability purposes, which are required over fewer hours.

10 The amount of energy used by a power generator to produce one kilowatt hour of electricity.

Gas Implication of San Onofre Nuclear Generation Station Closure

In early, 2012, the San Onofre Nuclear Generation Station (SONGS) Units 2 and 3 were taken offline due to problems discovered during maintenance inspections. Combined, the units at SONGS provided 2,200 MW of generating capacity to the Southern California region (Orange County and San Diego area). In December 2011, daily average natural gas demand on the SoCal Gas system was about 2,693 million cubic feet per day (MMcf/d). Since the closure of SONGS, demand on the SoCal Gas system rose to 2,950 MMcf/d in March 2012, a 257 MMcf/d increase from December 2011 natural gas demand, as shown in Figure 2. The California ISO reported that thermal generation from other sources also increased by more than 1,000 MW. Having ample available natural gas storage inventory levels and spare interstate pipeline capacity was likely key in ensuring that additional demand for natural gas was met with no reliability issues.

During the summer of 2012, the generation needed to make up for the loss of SONGS energy came almost entirely from the fossil-fuel plants in Southern California that do not use once-through-cooling. 11 In addition, Huntington Beach units 3 and 4 (452 MW) were converted from generation capacity to reactive support devices. 12 Increased transmission capacity from Sunrise Powerlink and Barre-Ellis also helped ensure power quality and reliability. All these efforts along with energy efficiency, and the potential to enact demand response and Flex Alerts helped to ensure that load was met reliably in the Southern California region for the summer of 2012.

Figure 2: SoCal Gas System Natural Gas Demand

In June 2013, Southern California Edison Company made the decision to permanently close and decommission SONGS. California will need to make up for the loss of this generating capacity with natural gas, renewable resources, and purchased power in the immediate years ahead. Governor Brown established a task force to develop and assess options to shore up local area capacity requirements in the absence of SONGS. A draft plan was released in August 2013. In early 2013, the California Public Utilities Commission (CPUC) issued a revised scoping order and assigned commissioner ruling, which focus on the need for resource procurement authority for capacity to satisfy local capacity requirements with SONGS offline. 13

11 The State Water Resources Control Board implemented a policy in May 2014 to phase out the use of once-through-cooling in coastal power plants that use ocean water. As a result, 20,704 MW of natural gas-fired generation will need to be retired, retrofitted or repowered to satisfy the OTC policy if they can secure CPUC-approved power purchase agreements.

12 Reactive support device: A device that helps improve and maintain power quality by keeping current and voltage levels in phase within acceptable parameters.

Once-Through Cooling and Natural Gas

On May 4, 2010 the State Water Resources Control Board (SWRCB) approved a once-through cooling (OTC) policy that included many grid reliability recommendations made by the California Independent System Operator (California ISO), as well as a join implementation proposal developed by the Energy Commission, California Public Utilities Commission (CPUC), and California ISO. The Office of Administrative Law approved the policy on September 27, 2010, and it became an effective regulation on October 1, 2010. The OTC policy will require electric generators to reduce or eliminate the use of coastal or estuarine water to minimize the harmful impacts of cooling water intake structures on the environment. The OTC policy recognizes that some of these plants are critical for system and local reliability. They may also provide operational services needed to integrate renewable resources into the state's electric grid. Some power plant owners will repower their facilities and use dry cooling technologies to replace OTC, while others will retire their facilities altogether. The permanent closure of San Onofre Nuclear Generation Station in 2012 presents additional challenges to the grid especially in Southern California, which provided generating capacity and voltage support for the region. California's energy agencies are working closely together to evaluate reliability needs in this region and the potential to use a balanced portfolio of options, including natural gas plants and preferred resources, to replace OTC plants and SONGS. In the near-term, the need for additional natural gas for power generation in Southern California may put strains on natural gas infrastructure in the region. In the longer term, the total demand for natural gas for electric generation is expected to decline as newer more efficient natural gas plants replace older, less efficient gas plants and more renewable resources come on-line to displace natural gas generation. Some of this reduction is likely to be offset by the need to use natural gas plants to provide the operational flexibility - requiring them to run at lower efficiency - that is necessary for integrating increasing amounts of renewable resources